In the oil industry drilling, completion or working-over of wells, drill or tubing strings are used to physically enter and enable performance of desired work functions down hole. In drilling operations drill strings are generally categorized as drill stem or drill pipe and bottom hole assemblies. Drill pipe joint lengths vary in the range of 30 feet and are connected together by "tool joints" having a "box", or female thread on the upper end, and a "pin" or male thread on the down-hole end. Tool joints are commonly an "integral" type attached to the drill pipe by a friction or flash weld. A large drilling rig for deep drilling may have drill pipe sections in excess of 500 or 600 joints. Drill pipe makes up the principal length and investment of a given drill string.
Bottom hole assemblies represent a lesser overall footage of the drill string and are thick walled approximate 30 foot long tubular sections called "drill collars." Drill collars provide weight to be run on drill bits. Drill collars have larger and more rugged box and pin connections than drill pipe and the threads of these connections are machined from the body of the drill collar itself. Bottom hole assemblies may include various "subs" of relatively short length for crossover between dissimilar thread sizes or forms as between drill pipe and drill collars. Other subs might include bit subs for adapting a bit thread to a drill collar, stabilizer subs serve to center drill collars in the well bore and safety valves
A square or hexagonal cross section "kelly" passing through a roller kelly drive bushing seated in the rotary table serves to impart rotation to the drill string in the hole. A kelly saver sub is customarily screwed onto the lower end of the kelly and provides a wear thread for the repeated make and break of the kelly when adding drill pipe when drilling. Many offshore rigs now use a "top drive" in lieu of the rotary table and kelly while drilling and drill down an entire "stand" of three joints of drill pipe before a new connection is required.
The hole depths at which the bit is drilling or other types of down hole work is being conducted is presently determined by measurements taken by rig crewmen with a steel tape and are hand written and totaled by the driller in his tally book. In the case of drilling, these tallies are usually broken down by bottom hole assemblies, drill pipe and the amount of footage the kelly is in the hole using as a reference point, or datum, the top of the kelly drive bushing or top of the rotary table as zero elevation. The total of these three general categorizations therefore provides hole depth.
During normal drilling procedures, individual drill pipe joints, subs or drill collars are measured immediately prior to picking up for insertion in the well bore string. Similarly, joints are measured when laid down as to be later picked up or to be replaced by other drill string components. Over only short periods of time, errors invariably occur which are usually the cause of inadvertently omitting entries into the tally, arithmetic errors or incorrect measurements made or reported by crewmen. To check measured depth tallies, the common practice is to measure and tally each three joint stand stood back in the derrick when tripping out of the hole to replace a bit or other down hole tool. This tally of approximate 90 foot stands, including bottom hole assembly stands, is used as a check of depths and serves to check and correct faulted tallies.
Due to tally errors being common, it is normal good practice to maintain a count of total joints of drill pipe on a rig when drilling starts and when drilling has progressed, occasionally reconciling a count of tallied joints in the hole and joints on the pipe rack with the original inventory. Hole depth is critical for geological reference and for operations such as when casing a hole in order to establish the amount of casing required to be landed at the correct depth. For these reasons, accurate pipe tallies of both joint quantities and total lengths are important and much expensive rig time is spent checking and rechecking such tallies.
Drill stem retirement from service is frequently necessitated by wear on the outside diameters of pipe, tool joints and drill collars which reduces wall area and both tensile and torsional load capacity; excessive corrosion or erosion; and physical damage from poor handling practice. Also of concern is the potential development of cracks or complete failure due to stress and fatigue especially in corroded, worn and thinner walled pipe.
Drill pipe life has traditionally been evaluated in terms of total feet of hole drilled by the composite several hundred joints that make up a given string of pipe. Service life of bottom hole assembly components is usually limited by outside diameter wear or from the repeated re-machining connection threads to eventually cause too short an overall length for handling by the derrick man in the derrick. Therefore drill collar or bottom hole assembly service factor measurements, such as cumulative footage drilled or fatigue damage, may not be generally as important as for drill pipe.
Although an identification serial number may be stenciled on each joint in a non-wear area, it is virtually impossible for field crews to keep track of individual joint usage whereby the total footage each joint drills may be manually recorded and accumulated. For this reason down hole service and wear is not evenly distributed to each individual joint of an entire drill string and some joints invariably receive much greater service than others. Equalizing service presents even more difficult problems if a portion of a drill string is lost in the hole and new pipe is added and indistinguishably mixed into an existing string.
Disproportionate down hole service may often be recognized by outside diameter wear but all too frequently, particularly in deviated holes, fatigue damage may become a deciding factor in the decision to retire drill pipe. Present day drill pipe inspection methods are capable of measuring wall wear or the extent of internal pitting but can only detect fatigue in the form of cracks already initiated in service. When a few cracks begin to appear in successive routine inspections, it is currently necessary to assume every joint in the string has been subjected to identical fatigue damage and the entire string requires retirement from service.